Chemical process for sulfur reduction of hydrocarbons

ABSTRACT

Treatment of hydrocarbon streams, and in one non-limiting embodiment refinery distillates, with high pH aqueous reducing agents, such as borohydride, results in reduction of the sulfur compounds such as disulfides, mercaptans and thioethers that are present to give easily removed sulfides. The treatment converts the original sulfur compounds into hydrogen sulfide or low molecular weight mercaptans that can be extracted from the distillate with caustic solutions, hydrogen sulfide or mercaptan scavengers, solid absorbents such as clay or activated carbon or liquid absorbents such as amine-aldehyde condensates and/or aqueous aldehydes.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication No. 62/323,120 filed Apr. 15, 2016, incorporated herein byreference in its entirety.

TECHNICAL FIELD

The present invention relates to the removal of sulfur compounds fromhydrocarbon streams, and more particularly relates, in one non-limitingembodiment, to methods for removing sulfur compounds from a hydrocarbonstreams using a reducing agent.

TECHNICAL BACKGROUND

Sulfur, generally in the nature of organosulfur molecules, is anundesirable contaminant in many hydrocarbon streams and volumes havinghydrocarbon carbon chain lengths of from C1 to C30, some of which may beutilized as or in fuels containing hydrocarbon molecules having C1-C12.

Additives currently used to reduce sulfur content only work on inorganicforms of sulfur (mainly hydrogen sulfide, H₂S) or low molecular weight(C1-C4) mercaptans. To remove high molecular weight (C5+) mercaptans,disulfides, thioethers and other sulfur compounds, the literaturesuggests oxidizing agents, such as a peroxide, e.g. hydrogen peroxide,is needed to convert the sulfur species into water soluble sulfoxides orsulfones which can be extracted from the hydrocarbon.

Future gasoline specifications in the United States require sulfurcompounds to be reduced to very low levels. The levels are low enoughthat gasoline blend components such as butanes containing sulfurcompounds will make the finished gasoline fail sulfur limits. Refinersdesire to limit their capital expenditures and seek alternatives to thebuilding of additional hydrotreating capacity, so they are seekingalternatives to remove these sulfur compounds from their distillates.

It would be desirable to remove sulfur compounds from refinerydistillate streams using an alternative process to those presently inuse.

SUMMARY

There is provided in one non-limiting embodiment a method for removing asulfur compound from a hydrocarbon stream containing the sulfur compoundwhere the method includes contacting the hydrocarbon stream with anamount of a reducing agent effective to react with the sulfur compoundto form at least one reaction product in a treated hydrocarbon stream;and then removing the at least one reaction product from the treatedhydrocarbon stream. The sulfur compound includes, but is not necessarilylimited to, mercaptans having the formula R—S—H where R is a linear orbranched C1 to C4 alkyl group, carbon disulfide (CS₂), carbonyl sulfide(COS), dialkyl sulfides having the formula R¹—S—R² where R¹ and R² areindependently linear or branched C1 to C4 alkyl groups, dialkyldisulfides having the formula R¹—S—S—R², and combinations thereof. Thehydrocarbon stream comprises liquid or gas hydrocarbons including, butnot necessarily limited to, C1 to C12 alkanes, C2 to C12 alkenes,liquefied petroleum gas, natural gas, fuel gas, flare gas, naphtha,gasoline, kerosene, and mixtures thereof. The reducing agent mayinclude, but is not necessarily limited to, borane (BH₃); diborane(B₂H₆); complexes of borane or diborane with Lewis bases selected fromthe group consisting of ethers, dialkyl sulfides, amines, alcohols, andmixtures thereof; inorganic borohydride salts having the formula M¹BH₄where M¹ is selected from the group consisting of Li, Na, and K, orhaving the formula M²(BH₄)₂ where M² is selected from the groupconsisting of Mg, Ca, and Zn; cyanoborohydrides having the formulaM¹BH₃CN or having the formula M²(BH₃CN)₂; organic borohydrides havingthe formula M¹BR³ ₃H and R³ is independently selected from the groupconsisting of linear or branched C1 to C3 alkyl groups and a carboxylategroup having the formula R⁴C(O)O— and R⁴ is selected from the groupconsisting of linear or branched C1 to C9 alkyl groups; and combinationsthereof.

In an alternative non-restrictive version there is provided a treatedhydrocarbon stream that includes liquid or gas light hydrocarbonsselected from the group consisting of C1 to C12 alkanes, C2 to C12alkenes, liquefied petroleum gas, natural gas, fuel gas, flare gas,naphtha, gasoline, kerosene and mixtures thereof, and at least onesulfur compound as defined above, and at least one reducing agent asdefined above, where the reducing agent is present in an amounteffective to react with the sulfur compound to form at least onereaction product.

In another non-limiting embodiment the methods are practiced at high pH,where the reducing agent is in an aqueous solution and has a high pHdefined as ranging from about 7 to about 14, alternatively at 7 orabove. In one non-limiting embodiment, a basic pH aqueous solutioncontains borohydrides, but these borohydrides are reactive toward acid.Higher pH prevents the borohydride from decomposing by forming hydrogengas.

DETAILED DESCRIPTION

It has been discovered that treatment of hydrocarbons, particularlyrefinery distillates, with a reducing agent, in a non-limitingembodiment, a high pH aqueous borohydride, results in the reduction ofthe sulfur compounds such as disulfides, mercaptans and thioethers thatare present to give easily removed sulfides. The treatment converts theoriginal sulfur compounds into hydrogen sulfide (H₂S) or low molecularweight mercaptans that can be extracted from the distillate with causticsolutions, hydrogen sulfide or mercaptan scavengers or solid absorbentssuch as clay or activated carbon or liquid absorbents, such asamine-aldehyde condensates and aqueous aldeydes. In one expectednon-restrictive practice, the borohydride solution is injected into thedistillate in rundown lines from refinery production units to tankageand/or can be injected in recirculation loops of storage tanks. Goodmixing of the borohydride with the distillate is helpful to facilitatereaction and additionally there needs to be a downstream separationpoint to remove the aqueous solution. Separators, centrifuges or evenstorage tank bottoms are all adequate to collect the aqueous byproducts.Optionally passing the treated and dehydrated hydrocarbon through asubsequent filtration or in contact with a solid or liquid absorbent (innon-limiting embodiments, clays, carbon, zeolites, amine-aldehydecondensates and the like) removes any residual borohydride and thereaction product yielding lower sulfur content distillate able to meetall sales specifications. Alternatively, the separation could also beaccomplished using an extraction technique such as a contact tower orcaustic wash unit.

In another non-limiting embodiment with more specificity, a solution ofa borohydride in caustic is injected into a hydrocarbon containingorganic sulfur compounds such as disulfides (R—S—S—R), thioethers(R—S—R), carbonyl sulfide (COS) or carbon disulfide (CS₂). Theborohydride is thought to reduce the sulfur compounds to inorganic H₂Sor to low molecular weight mercaptans which are then removed from thehydrocarbon by the caustic in the borohydride solution or alternativelyby adding an additional H₂S scavenger (including, but not necessarilylimited to, triazines; metal carboxylates such as those including themetals Zn, Cu, and/or Fe; oxides, hydroxides or carbonates) to thedistillate. The hydrogen sulfide scavengers should be aqueous oralternatively formulated in a hydrocarbon insoluble solvent so thesulfur-containing reaction products can be separated from thehydrocarbon. Any separation equipment used for oil/water separation canbe used in the process described herein. A subsequent or final step maybe where the treated hydrocarbon is passed through and/or contacted withan absorbent that is used to remove any residual borohydride, sulfurcompound or H₂S scavenger to yield a hydrocarbon distillate with a muchreduced sulfur content.

Other reducing agents besides sodium borohydride include, but are notnecessarily limited to, borane (BH₃), borane complexes with ethers,amines and other complexing agents, lithium aluminum hydride, sodiumhydride, calcium hydride and other metal hydrides may be substituted forthe borohydride above. Metal hydrides such as lithium aluminum hydride,sodium hydride and calcium hydride may be too sensitive to air andmoisture sensitive in some cases to be used in the application. In othercircumstances they may be so strong of a reducing agent that they willreduce the olefins being treated. Catalysts including, but notnecessarily limited to, a Lewis acid (e.g. aluminum chloride, ferricchloride, zinc chloride) may also be used to facilitate the reduction ofthe sulfur compounds. The sulfides formed by the reduction may beremoved via simple gravity separation of an aqueous or other immisciblephase or by use of solid absorbent beds such as metals (zinc, iron) onabsorbents (clay, zeolites, carbon). Alternatively the sulfides may beremoved by contact with liquid absorbents including, but not necessarilylimited to, amine-aldehyde condensates and/or aqueous aldehydes, and thelike. Treatment can be in stages or a single process. For example if thehydrocarbon contains hydrogen sulfide in addition to the other sulfurcompounds, it can be treated first with a hydrogen sulfide scavenger toremove the H₂S and then treated with the borohydride to reduceadditional sulfur compounds and then finally filtered or run through anextraction process to remove the reduced sulfur products.

Suitable sulfur compound-containing refinery distillate streams include,but are not necessarily limited to, liquid or gas hydrocarbons selectedfrom the group consisting of C1 to C12 alkanes, including methane, C2 toC12 alkenes, liquefied petroleum gas, natural gas, fuel gas, flare gas,naphtha, gasoline, kerosene and mixtures thereof; possibly up to C16 fordiesel fuels. However, the methods described herein are expected to alsobe effective in oilfield applications, including, but not necessarilylimited to, removing sulfur compounds from oilfield condensates, naturalgas, and the like, The methods described herein may also be effective intreating natural gas liquids (NGL) or liquid petroleum gas (LPG) withinor as it is withdrawn from a storage facility.

The sulfur compounds that may be removed from the refinery distillatestreams include, but are not necessarily limited to, mercaptans havingthe formula R—S—H where R is a linear or branched C1 to C4 alkyl group,carbon disulfide (CS₂), carbonyl sulfide (COS), dialkyl sulfides havingthe formula R¹—S—R² where R¹ and R² are independently linear or branchedC1 to C4 alkyl groups, dialkyl disulfides having the formula R¹—S—S—R²where R¹ and R² are as previously defined.

With more specificity, suitable reducing agents include, but are notnecessarily limited to, borane (BH₃); diborane (B₂H₆); complexes ofborane or diborane with Lewis bases selected from the group consistingof ethers, dialkyl sulfides, amines, alcohols, and mixtures thereof;inorganic borohydride salts having the formula M¹BH₄ where M¹ isselected from the group consisting of Li, Na, and K, or having theformula M²(BH₄)₂ where M² is selected from the group consisting of Mg,Ca or Zn; cyanoborohydrides having the formula M¹BH₃CN where M¹ is aspreviously defined or having the formula M²(BH₃CN)₂ where M² is aspreviously defined; organic borohydrides having the formula M¹BR³ ₃Hwhere M is as previously defined and R³ is independently selected fromthe group consisting of linear or branched C1 to C3 alkyl groups and acarboxylate group having the formula R⁴C(O)O— and R⁴ is selected fromthe group consisting of linear or branched C1 to C9 alkyl groups; andcombinations thereof. That is, there can be combinations of R andR⁴C(O)O— on the same boron, such that all R³s can be alkyl, all R³s canbe R⁴C(O)O—, or there can be combinations of the two.

Also for the purposes of the present application, the term “caustic” isdefined broadly to mean a strong base (alkaline) substance including,but not limited to sodium hydroxide (NaOH), potassium hydroxide (KOH),and lithium hydroxide (LiOH); but also specifically including anycompound now known or later discovered to be useful for extracting orotherwise removing a sulfur compound from a refinery distillate fluidstream. However, in another non-limiting embodiment “caustic” is definedas selected from the group consisting of sodium hydroxide, potassiumhydroxide, lithium hydroxide, and combinations thereof. It will beappreciated that the fact that a liquid washing phase, which in onenon-limiting embodiment is a caustic liquid, does not encompass allliquids that are basic which contain relatively small amounts of analkali metal hydroxide or alkanolamine, alkyl amine, and/or alkazides toadjust the pH of the liquid. In the caustic liquids used herein, thecaustic or basic materials, in the case where alkali metal hydroxide isused in the basic system, the amount of alkali metal hydroxide may beabout 50 wt % or less based on the water used to treat the refinerydistillate stream; alternatively about 15 wt % or less; and in anothernon-limiting embodiment, about 12 wt % or less. Many of the suitablecaustic solutions will have high levels of KOH and/or NaOH. Thesecaustic solutions have a much higher density than the hydrocarbons beingtreated to improve separation of the two phases. The density differencebetween caustic and the hydrocarbon improves the settling rate and givesbetter separation. The contacting of the reducing agent with therefinery distillate stream may be in an aqueous solution having a pHfrom about 7 independently to about 14; alternatively a pH from about 10to about 13.5. In another non-limiting embodiment, the basic aqueoussystem containing the reducing agent may have a pH of 9 or greater;alternatively 9.5 or greater, and in a different non-limiting embodimentof 10 or greater. In another non-restrictive version, these thresholdsmay be used together with the pH ranges given previously as alternativethresholds for suitable alternative pH ranges. As noted, these liquidsare aqueous. It is fortunate that while borohydrides are strong reducingagents, they may be employed in aqueous solutions.

It will be appreciated that the reducing agents herein exclude metalhydrides such as aluminum hydrides, NaH, LiH, and CaH₂, since they areoften too water and/or air sensitive to be applied in the methoddescribed herein.

In some embodiments of the methods herein, a refinery distillate stream,is treated with a reducing agent. In a non-restrictive example, carbonylsulfide (COS) can be removed from a refinery distillate stream, by theaddition of sodium borohydride (NaBH₄) as the additive. When COS gas ispresent in a solution of NaBH₄, the COS will react with the NaBH₄ andthe reaction is irreversible. The reaction can be illustrated asfollows:

O═C═S+H⁻→O═CH—S⁻ or ⁻O—CH═S  (1)

The reaction products are a more polar species, that is a morewater-soluble species and can be washed away by the aqueous caustic.

The effective amount of reducing agent added is any amount that iseffective to bind up and/or react with the sulfur compound and at leastpartially convert it to a reaction product that can be removed. In onenon-restrictive version, the effective amount of the reducing agent isup to two times the stoichiometric ratio of the reducing agent to thesulfur compound; alternatively, the effective amount ranges from about0.8 to about 1.8 times the stoichiometric ratio of the reducing agent tothe sulfur compound. In another non-limiting embodiment, the effectiveamount of NaBH₄, or other reducing agent, is a molar ratio of NaBH₄ toCOS of from about 0.02:1 independently to about 50:1 based on the amountof sulfur compound in the process stream; alternatively, the molar ratioranges from about 0.1:1 independently to about 40:1. The word“independently” as used with respect to a range herein means that anylower threshold may be used with any upper threshold to provide asuitable alternative range. The theoretical amount is a 1:1 mole ratioof NaBH₄ to COS, as shown in reaction (1). In one non-limitingembodiment the amount of NaBH₄ to COS is in excess of a mole ratio of1:1.

In some cases, the reducing agent solution will be contacted with thehydrocarbon and it will be both scavenger which converts the sulfurcompounds present into another form and it will also be the solutionwhich extracts the sulfur compounds formed (reaction products) away fromthe hydrocarbon. In other, different cases, a second treatment of thehydrocarbon with a solid or liquid absorbent will be conducted to removethe sulfur compounds formed by the borohydride (reaction products). Thatis, in some non-limiting embodiments the hydrocarbon will simply becontacted with the reducing agent (e.g. borohydride) solution and itwill be both scavenger and absorbent. In other different,non-restrictive embodiments, the treated hydrocarbon will be passedthrough the solid/liquid absorbent to be sure all sulfur compounds (andscavenger) are removed. With respect to dose rates, if the reducingagent (e.g. borohydride) solution is simply injected into a hydrocarbonstream a ppm of scavenger to ppm of sulfur ratio based on the chemistrymay be provided. However if the hydrocarbon is bubbled through asolution of the reducing agent (e.g. borohydride) then the amount ofreducing agent solution will be relatively large in the tower ascompared with the relatively small amount of hydrocarbon migratingthrough the aqueous solution of reducing agent

In the non-limiting case of the reducing agent (in this caseborohydride) solution being directly injected into the sour hydrocarbon,one non-restrictive ppm dosage range would be from about 0.5independently to about 10 ppm borohydride per ppm of sulfur to beremoved; alternatively from about 1 independently to about 5 ppmborohydride per ppm sulfur to be removed.

In tower applications where sour hydrocarbon is bubbled through theborohydride solution, the ratio will be higher as there are only smallbubbles of the hydrocarbon migrating up through the borohydride solutionin the tower. There will be a relatively large volume of the borohydridesolution present since it fills the contact tower and only a relativelysmall amount of sulfur compound present in the small bubbles of thehydrocarbon migrating their way through the borohydride solution. Inthis latter case, the ratio of borohydride solution to hydrocarbon canrange from about 95 vol % borohydride scavenger independently to as lowas 5 vol % borohydride to sour gasoline; alternatively on the order ofabout 10 independently to about 50 vol % borohydride solution to sourhydrocarbon. It will be appreciated that for a different reducing agentthan borohydride, these dosage ranges will be different due to differentstoichiometery.

Generally, the additives will be present at a level in the treatedrefinery distillate stream such that the concentration of sulfurcompound in the stream is lowered to from about 1 or less than 1independently to about 5 ppm. In other embodiments the concentrationafter treatment is from about 0.1 independently to about 100 ppm. In onenon-limiting embodiment, there may remain from about 1 to about 2 ppmsulfur in the treated hydrocarbon and gasoline specifications may stillbe met. In one non-limiting embodiment the highest levels of sulfurexpected to be treated in the hydrocarbon stream will be on the order of500 ppm and it may be desired to reduce sulfur content to less than 1ppm. Alternatively an expected starting sulfur content of 100 ppm orless which can be reduced to 3 ppm or less, and in a differentnon-restrictive version the starting sulfur content may be about 50 orless, which can be reduced to 5 ppm or less.

The temperature range for the contacting by the reducing agent will onlybe limited by the additive properties. The stream being treated cannotbe so hot that the water in the additive is flashed off and leave solidborohydride behind. Conversely, the stream cannot be so cold that theadditive freezes and does not mix with the hydrocarbon stream. Ingeneral, it is expected that relatively hotter will be better thanrelatively colder since kinetics improve as temperature increases, butagain in general, the temperature cannot be so hot that the solvent(water) flashes off.

In addition to the additives already described, the additives usedherein may include other compounds known to be useful in sulfur compoundremoval methods such as dispersants, defoamers, and the like. Anycompound that does not have an undesirable interaction with theadditive's ability to reduce or remove the sulfur compound may be usedwith at least some embodiment of the methods and compositions describedherein. A defoamer in particular might be used if a gas is beingtreated. Additionally, a demulsifier may be employed if the separationstep used involves settling in a storage tank. For instance, there couldbe some emulsion present that was generated by contact of the aqueousand hydrocarbon phases. A demulsifier will help break the water awayfrom the hydrocarbon.

To reduce the sulfur content of the treated refinery distillate stream,a separation step is required. The separation can utilize solidabsorbents like carbon, clay and zeolites or alternatively theseparation can utilize an extraction with caustic solutions or water.The extraction solvent can optionally be part of the borohydrideadditive (i.e. the borohydride may be formulated in caustic like theBaker Hughes Additive C additive used in the lab test) or it may bepresent in a contact tower, settling tank, water/caustic wash vessel,and the like. Small particle size absorbents (powdered carbon vs. carbonpellets) are advantageous in an absorbent. Suitable powders may have aparticle size of equal to or less than 0.075 mm, suitable granular sizesmay have a particle size of 1.2-1.4 mm and suitable pellets may have aminimum size of 4 mm. The only necessary condition for an extractionsolvent is that it should have a pH of neutral or basic (i.e. equal toor greater than 7.0). Acids decompose borohydrides, so an acidic pHwould cause some problems of hydrogen generation in the process.Suitable clays include, but are not necessarily limited to, attapulgite,montmorillonite, bentonite, and the like.

As noted, removing the reaction products from the treated refinerydistillate stream may include any method known to those skilled in therelevant art, such as by using a clay and/or carbon. The use of carbon,such as activated carbon, carbon powder, granulated carbon, otherparticulate carbon, is a consideration for the separation step becauseit has been discovered that more sulfur can be removed by carbon whenthe hydrocarbon has been treated with the reducing agent describedherein. Without being limited to any specific explanation, this may bebecause the reducing agent modifies the sulfur compounds present suchthat they are better removed by absorption on the carbon media. In thepresent method, the sulfur compounds are modified before contact withthe carbon and the result is that even the modified carbon can absorbmore of the sulfur species produced with the reducing agents describedherein. The amount of absorbent needed will vary depending on the typeof sulfur compounds being removed. Some sulfur compounds with large “R”groups, i.e. alkyl groups, for example will take up more space on thecarbon than sulfur compounds with small “R” groups. The overall capacityof the absorbent will depend on the amount of each sulfur compoundpresent in the hydrocarbon refinery distillate stream being treated.

With respect to the optional liquid absorbents to remove the reactionproducts formed by the treatment with the caustic/borohydride solution,suitable amine-aldehyde condensates include, but are not necessarilylimited to monoethanolamine (MEA) triazines, methylamine (MA) triazines.Suitable aqueous aldehyde solutions include, but are not necessarilylimited to, glyoxal, glycolaldehyde, glutaraldehyde and the like. Theamount of liquid absorbent may range from about 1 independently to about90% by volume of hydrocarbon being treated; alternatively from about 10independently to about 50% by volume of the hydrocarbon being treated.The Examples 52-60 reported below used 10% volume of liquid absorbent to90% hydrocarbon which fits in the narrower range. Contacting thehydrocarbon with just the caustic solution works well, but the capacityto extract the reaction products formed in the hydrocarbon is limited.This leads to a high replacement rate of the additive if only thecaustic solution alone is used. The reaction products such as mercaptideions may stay in the treated hydrocarbon as the caustic/hydrocarbonsolution separates. It should be noted that not all liquid absorbentswork. Inorganic oxidizers such as ferric chloride and simpleneutralizing amine, such as methyldiethanolamine, have been tried andthey do not work.

The process described herein also has the potential to remove highermercaptans which current scavengers do not remove. Thus, higher boilingfractions can be treated to remove these corrosive materials using thismethod.

The following examples are provided to illustrate the present method.The examples are not intended to limit the scope of the present methodand they should not be so interpreted. Amounts are in weight parts orweight percentages unless otherwise indicated.

Sulfur Scavenger Test Procedure

-   -   1.) Light Virgin Naphtha (LVN) as freshly received from refinery        is dosed with additional sulfur (S) compounds. These include        1-butanethiol, dimethyl disulfide, di-ethyl sulfide, and carbon        disulfide.        -   a. The desired S compound is injected directly into a            measured volume of LVN sample using an appropriately sized            syringe at dose required to attain targeted ppm level (i.e.,            100-1,000+ppm)        -   b. The syringe (i.e., 10 uL-1 mL) shall reach below the            surface of the LVN sample as to limit escape into the            container headspace during transfer.        -   c. Use a different clean syringe/microdispenser/cannula for            each S compound to avoid the potential for            cross-contamination.        -   d. The container (e.g., 1 L clear glass bottle with screw-on            cap) shall be filled close to the top to limit the more            volatile S compounds from evolving to the vapor phase.        -   e. To ensure a homogenous mix, place the capped bottle in a            horizontal position on an orbital shaker at 220 rpm for 30            seconds.    -   2.) Using an appropriately sized syringe, dose empty (e.g. 6 oz.        graduated prescription bottle) with desired chemical additive.        -   a. In this case, either Baker Hughes Additive C (12.5% by            wt. sodium borohydride) or Baker Hughes Additive A (45% by            wt. potassium hydroxide)        -   b. Fill dosed bottle to mark (e.g. 100 mL) with LVN to            achieve targeted treat rate (i.e., ppm v/v)    -   3.) Mix well to insure contact of chemical additive with S        compounds in the LVN.        -   a. Lay capped bottles in a horizontal position on an orbital            shaker set at 220 rpm for 2 hour.        -   b. At this point, if the sample is to be filtered then go            immediately to Step #4, otherwise proceed to Step #3c and            then onto Step #5.        -   c. After thoroughly mixing let samples sit quietly            over-night (about 16 hours) to allow any aqueous reaction            products to potentially settle out.    -   4.) Filtered samples are gravimetrically allowed to migrate        through activated carbon.        -   a. w/w ratio 1:3.2 carbon:LVN.        -   b. Set a small amount of clean glass wool (0.7-0.8 gm) in            the bottom of a funnel (e.g. a 100 mm powder funnel) to hold            the powdered carbon in place.        -   c. Weigh 25 gm carbon into funnel.        -   d. Slowly and evenly pour LVN through carbon filter.        -   e. Collect filtered LVN into smaller bottle (e.g. a 2 oz.            clear glass bottle with a screw-on cap) until filled to top            to limit headspace.    -   5.) Labeled sample bottle is then tested for weight percent (or        ppm) total sulfur and/or sulfur speciation.        -   a. Do not agitate/re-mix sample bottle.        -   b. Aliquot for testing will be drawn from upper portion of            sample and any aqueous bottoms should not be disturbed.        -   c. Total Sulfur (i.e., Sulfur in Oil) to be determined by            Energy Dispersive X-Ray Fluorescence (ED-XRF) (i.e., use the            ASTM D4294 method).        -   d. Sulfur Speciation to be determined by Gas            Chromatography-Sulfur Selective Detection (GC-SSD) (i.e.,            use the ASTM D5623 method).

Examples 1-23

The Sulfur Scavenger Test Procedure described above was used to measurethe impact of a sodium borohydride additive designated Additive C, whichwas 12 wt % sodium borohydride in 40 wt % NaOH in water. The results aregiven in Table I. Abbreviations are given below Table I.

TABLE I EXAMPLES 1-23 Effect of Additive C Additive on Sulfur RemovalDose % S Ex. Additive (ppm) Weight % S Comment Removed 1 Naphtha blank 00.383 wt % Baseline 0% (untreated) 2 Additive A 300 0.348 wt % Smalllevel of activity 9% with caustic alone Test Conditions: Naphthacontaining 1000 ppm C4SH + 1000 ppm DMDS + 1000 ppm DES + 1000 ppm CS2.Test temp = Room Temperature (RT, ~75° F.) 3 Naphtha blank — 0.512 wt %Baseline 0% (untreated) 4 Additive A 3,000 0.346 wt % Higher dose ofcaustic 32%  gives better activity Test Conditions: Naphtha containing1000 ppm C4SH + 1000 ppm DMDS + 1000 ppm DES + 1000 ppm CS2. Test temp =RT (~75° F.) 5 Additive C 4,000 0.356 wt % Baseline 0% 6 Additive C6,000 0.260 wt % Higher dose of 27%  Additive C = better performance 7Additive C 12,000 0.258 wt % Higher dose of 28%  Additive C = levelingoff performance Test Conditions: Naphtha containing 3000 ppm DMDS. Testtemp = RT (~75° F.) 8 Naphtha blank — 87.3 ppm Baseline 0% (untreated) 9Additive C 100 85.8 ppm Small level of activity 2% on removal of DES 10Additive C 500 88.1 ppm No activity on DES −1%  removal 11 Additive C1,000 84.1 ppm Higher dose of 4% Additive C = better performance 100 ppmDES only added to each sample as only sulfur compound. Test temp = RT(~75° F.) 12 Naphtha blank — 290.1 ppm Baseline 0% (untreated) 13Additive C 100 300 ppm No activity on CS2 −3%  removal 14 Additive A 100300.3 ppm No activity on CS2 −4%  removal 100 ppm CS2 only added to eachsample as only sulfur compound. Test temp = RT (~75° F.) 15 Naphthablank — 92.4 ppm Baseline 0% (untreated) 16 Additive C 100 89.6 ppmSmall level of activity 3% on C4SH removal 17 Additive A 100 88 ppmSmall level of activity 5% on C4SH removal 100 ppm C4SH only added toeach sample as only sulfur compound. Test temp = RT (~75° F.) 18 Naphthablank — 96.6 ppm Baseline 0% (untreated) 19 Additive C 100 195.8 ppm Badtest result? −103%    20 Additive A 100 95.3 ppm Small level of activity1% on DES removal 100 ppm DES only added to each sample as only sulfurcompound. Test temp = RT (~75° F.) 21 Naphtha blank — 190.5 ppm Baseline0% (untreated) 22 Additive C 100 94.5 ppm Excellent removal of 50%  CS223 Additive A 100 192.4 ppm No activity −1%  100 ppm DMDS only added toeach sample as only sulfur compound. Test temp = RT (~75° F.) Additive A= 45% KOH in water Additive B = zinc octanoate Additive C = 12% sodiumborohydride in 40% NaOH in water Additive D = 50% aluminum chloridehydroxide in water Additive E = 31% polyaluminum chloride in water CS2 =Carbon disulfide C4SH—n-butyl mercaptan DES = Diethylsulfide DMDS =Dimethyldisulfide

TABLE II EXAMPLES 24-42 Carbon Filtration Used to Remove S SpeciesPresent/Formed by Additive C Dose % S Ex. Additive (ppm) Weight % SComment Removed 24 Carbon filtered, — 0.129 wt % Baseline  0% untreatednaphtha 25 Additive C 3,000 0.109 wt % Additive C helps 16% carbonremove S Species 26 Additive A 3,000 0.202 wt % Caustic alone hurts S−57%  removal by carbon Test Conditions: Naphtha containing 1000 ppmC4SH + 1000 ppm DMDS + 1000 ppm DES + 1000 ppm CS2 1:4 ratio filtermedia to naphtha. Test temp = RT (~75° F.) 27 Carbon filtered, — 140 ppmBaseline  0% untreated naphtha 28 Additive C 100 112.5 ppm Good activityon CS2, 20% Additive C helps carbon remove S species 29 Additive A 100135.4 ppm No/poor activity  3% 100 ppm CS2 only added to each sample asonly sulfur compound, 1:4 ratio filter media to naphtha for filtrationprocedure. Test temp = RT (~75° F.) 30 Carbon filtered, — 31.5 ppmBaseline  0% untreated naphtha 31 Additive C 100 37.7 ppm Less harm tocarbon −20%  filtering than caustic alone 32 Additive A 100 44.7 ppmCaustic harms C4SH −42%  removal by carbon filtering 100 ppm C4SH onlyadded to each sample as only sulfur compound, 1:4 ratio filter media tonaphtha for filtration procedure. Test temp = RT (~75° F.) 33 Carbonfiltered, — 58.8 ppm Bad Blank*  0% untreated naphtha 34 Additive C 100107.5 ppm No Activity/Additive C −83%  hurts carbon removal of DES 35Additive A 100 100.1 ppm Less harm to carbon −70%  removal of DES thanwith Additive C 100 ppm DES only added to each sample as only sulfurcompound, 1:4 ratio filter media to naphtha for filtration procedure.Test temp = RT (~75° F.) 36 Carbon filtered, — 106.1 ppm Baseline  0%untreated naphtha 37 Additive C 100 34.5 ppm Good activity on 67% DMDS,Helps carbon removal of DMDS 38 Additive A 100 37.9 ppm Caustic slightlyless 64% active in helping carbon remove DMDS species 100 ppm DMDS onlyadded to each sample as only sulfur compound, 1:4 ratio filter media tonaphtha for filtration procedure. Test temp = RT (~75° F.) 39 AdditiveC + 4,000 0.268 wt % Baseline  0% Carbon filtered 40 Additive C +4,000 + 0.172 wt % Zinc Octanoate helps 36% Additive B + 2,000 improveDMDS Carbon filtered removal by Additive C + carbon filtering 41Additive C + 4,000 + 0.152 wt % Aluminum salts help 43% Additive D +2,000 improve DMDS Carbon filtered removal by Additive C and Carbonfiltering 42 Additive C + 4,000 + 0.186 wt % Aluminum salts help 31%Additive E + 2,000 improve DMDS Carbon filtered removal by Additive Cand Carbon filtering 3000 ppm Dimethyl disulfide (DMDS) only sulfurcompounds added to give wt % sulfur listed, 1:4 ratio filter media tonaphtha. Test temp = RT (~75° F.) *This result came back inconsistentwith other data. It needs to be rerun to be sure of the result.

TABLE III EXAMPLES 43-51 Comparison of Common Filter Media to Remove SSpecies Ex. Additive PPM Sulfur Comment % S Removed 43 Blank @ 75° F.613.5 ppm Baseline 0% 44 Blank @ 75° F. filtered 291 ppm Powdered Carbonis 53%  through carbon powder best filter media for S WTX removal 45Blank @ 75° F. filtered 595.2 ppm Poor S removal by 3% thru carbongranular granular carbon filter CPG LF media 46 Blank @ 75° F. filtered347.2 ppm Powdered Carbon is 43%  thru carbon powder BG best filtermedia for S HHH removal 47 Blank @ 75° F. + filtered 540 ppm Poor Sremoval by 12%  thru carbon granular granular carbon filter OLC media 48Blank @ 75° F. filtered 567.9 ppm Poor S removal by 7% thru carbongranular granular carbon filter Filter Scrub media 49 Blank @ 75° F. +filtered 592 ppm Poor S removal by 4% thru carbon pellets carbon pelletfilter Centaur HSV media 50 Blank @ 75° F. + filtered 586.9 ppm Poor Sremoval by 4% thru fine clay clay filter media attapulgite 51 Blank @75° F. + filtered 639 ppm Poor S removal by −4%  thru coarse clay clayfilter media attapulgite NOTE: The designations “WTX”, “CPG LF”, “BGHHH”, “OLC”, and “Centaur HSV” are trade names or trademarks ofCALGONCARBON ® Corp.

Examples 52-60 Liquid Absorbents of Reaction Products

In these experiments, 10 mls of a commercial aqueous sodium borohydridesolution was added to a separatory funnel with 90 mls of sour gasoline.The mixture was shaken by hand 100 times and then allowed to separate.The top hydrocarbon phase was sampled and tested by ASTM D 4952-02 (alsoknown as the doctor test) for active sulfur compounds and also analyzedfor total mercaptan content by ASTM D3227. The doctor test is a commonmethod used in the industry to rate the corrosivity of a hydrocarbontoward metals like copper and is a common specification forhydrocarbons. Customers will run the test and if the hydrocarbon failsthe test, they will know that it contains active or corrosive sulfurcompounds that have to be treated before the hydrocarbon can be put in apipeline, for example. After washing the gasoline with the borohydridesolution, the same gasoline was washed (shaken 100 times by hand) asecond time with 10 mls of a 48% active solution of MEA triazine inwater. The hydrocarbon phase was allowed to separate and then wassampled and analyzed by the doctor test and ASTM D3227. The results areshown in Table IV.

TABLE IV Examples 52-56 - Na Borohydride + MEA Triazine MEA Borohydridetriazine Volume of Doctor Mercaptan solution absorbent gasoline testcontent Ex. (mls) (mls) (mls) result (ppm) Comment 52 — — — Fail 80.4Untreated sour gasoline failed the doctor test and had a mercaptancontent of 80.4 ppm 53 — — 90 Fail 78.7 Gasoline washed with only 10 mlsof water without scavenger or absorbent - water is not effective inreducing mercaptan content or activity of hydrocarbon on the doctortest. 54  0 10 90 Fail 59.4 The liquid adsorbent (MEA triazine) removessome mercaptan from the gasoline but not enough to give a doctor testpass 55 10  0 90 Fail 23.2 The borohydride solution alone significantlyreduces gasoline mercaptan content but still not by enough to give apassing rating on the doctor test 56 10 10 90 Pass 16.5 Washing thegasoline with the borohydride solution and then washing the samehydrocarbon a second time with MEA triazine solution reduced themercaptan content enough that passing doctor test was obtained.

In a second set of experiments, both the borohydride and the MEAtriazine solutions from the Examples 52-56 above were reused and shakenwith fresh sour gasoline to see how many cycles could be run and stillget a passing doctor test. Thus, the same borohydride solution separatedfrom the tests above was shaken with fresh sour gasoline, allowed toseparate, sampled and tested by doctor test and ASTM D3227. If thegasoline failed the doctor test, it was shaken a second time with onlythe MEA triazine solution, allowed to separate, sampled and tested bydoctor test and for mercaptan content. The cycles of using spentborohydride and MEA triazine were repeated until a failing doctor testwas no longer obtained. Results are presented in Table V.

TABLE V Examples 57-60 - Na Borohydride + MEA Triazine Continued MEAVolume Borohydride triazine of Doctor Mercaptan solution solutiongasoline test content Ex. (mls) (mls) (mls) result (ppm) Comment 57 10 0 90 Fail 24.7 Borohydride solution from Ex. 55 above shaken with freshsour gasoline 58 (10) 10 90 Pass 17.3 Gasoline from Ex. 57 shaken withMEA triazine solution from Ex. 54 above 59 10  0 90 Fail 25.9Borohydride solution from Ex. 57 shaken with fresh sour gasoline 60 (10)10 90 Fail 21.6 Gasoline from Ex. 59 shaken with MEA triazine from Ex.58 above

The tests in Table V show that while the borohydride solution doesreduce the active sulfur content of the gasoline, it leaves enoughsulfur compounds behind that the treated gasoline fails the doctor test.Washing with a liquid adsorbent like the MEA triazine solution removessulfur compounds left behind by the borohydride washing and allows thegasoline to pass the test. The spent scavenger and absorbent can bereused for a number of cycles which noticeably improves the economics ofany treatment.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been demonstrated aseffective in providing configurations, methods, and compositions forremoving sulfur compounds from refinery distillate streams containingthem, for instance as demonstrated in the results of Tables I, II, andIII. However, it will be evident that various modifications and changescan be made thereto without departing from the broader scope of theinvention as set forth in the appended claims. Accordingly, thespecification is to be regarded in an illustrative rather than arestrictive sense. For example, the type of refinery distillate streams,the amounts and ratios of reducing agents, reaction products, sulfurcompounds, treatment procedures, reaction parameters, solid absorbents,liquid absorbents, and other components and/or conditions falling withinthe claimed parameters, but not specifically identified or tried in aparticular method, are expected to be within the scope of thisinvention. Further, it is expected that the method may change somewhatfrom one application to another and still accomplish the stated purposesand goals of the methods described herein.

The present invention may suitably comprise, consist or consistessentially of the elements disclosed and may be practiced in theabsence of an element not disclosed. For instance, there may be provideda method for removing a sulfur compound from a hydrocarbon streamcontaining the sulfur compound, where the method comprises, consistsessentially, of or consists of contacting the hydrocarbon stream with anamount of a reducing agent effective to react with the sulfur compoundto form at least one reaction product in a treated hydrocarbon stream,and removing the at least one reaction product from the treatedhydrocarbon stream, where the sulfur compound, the reducing agent, andthe hydrocarbon stream are as defined herein.

In another non-limiting instance, there may be provided a treatedhydrocarbon stream comprising, consisting essentially of, or consistingof, liquid or gas light hydrocarbons selected from the group consistingof C1 to C12 alkanes, C2 to C12 alkenes, liquefied petroleum gas,natural gas, fuel gas, flare gas, naphtha, gasoline, kerosene, andmixtures thereof; at least one sulfur compound selected from the groupconsisting of mercaptans having the formula R—S—H where R is a linear orbranched C1 to C4 alkyl group, carbon disulfide (CS₂), carbonyl sulfide(COS), dialkyl sulfides having the formula R¹—S—R² where R¹ and R² areindependently linear or branched C1 to C4 alkyl groups, dialkyldisulfides having the formula R¹—S—S—R² where R¹ and R² are aspreviously defined, and combinations thereof; and at least one reducingagent selected from the group consisting of borane (BH₃); diborane(B₂H₆); complexes of borane or diborane with Lewis bases selected fromthe group consisting of ethers, dialkyl sulfides, amines, alcohols, andmixtures thereof; inorganic borohydride salts having the formula M¹BH₄where M¹ is selected from the group consisting of Li, Na, and K, orhaving the formula M²(BH₄)₂ where M² is selected from the groupconsisting of Mg, Ca, and Zn; cyanoborohydrides having the formulaM¹BH₃CN where M¹ is as previously defined or having the formulaM²(BH₃CN)₂ where M² is as previously defined; organic borohydrideshaving the formula M¹BR³ ₃H where M is as previously defined and R³ isindependently selected from the group consisting of linear or branchedC1 to C3 alkyl groups and a carboxylate group having the formulaR⁴C(O)O—, and where and R⁴ is selected from the group consisting oflinear or branched C1 to C9 alkyl groups; and combinations thereof;where the reducing agent is present in an amount effective to react withthe sulfur compound to form at least one reaction product.

As used herein, the terms “comprising,” “including,” “containing,”“characterized by,” and grammatical equivalents thereof are inclusive oropenended terms that do not exclude additional, unrecited elements ormethod acts, but also include the more restrictive terms “consisting of”and “consisting essentially of” and grammatical equivalents thereof. Asused herein, the term “may” with respect to a material, structure,feature or method act indicates that such is contemplated for use inimplementation of an embodiment of the disclosure and such term is usedin preference to the more restrictive term “is” so as to avoid anyimplication that other, compatible materials, structures, features andmethods usable in combination therewith should or must be, excluded.

As used herein, the singular forms “a,” “an,” and “the” are intended toinclude the plural forms as well, unless the context clearly indicatesotherwise.

As used herein, the term “and/or” includes any and all combinations ofone or more of the associated listed items.

As used herein, relational terms, such as “first,” “second,” “top,”“bottom,” “upper,” “lower,” “over,” “under,” etc., are used for clarityand convenience in understanding the disclosure and do not connote ordepend on any specific preference, orientation, or order, except wherethe context clearly indicates otherwise.

As used herein, the term “substantially” in reference to a givenparameter, property, or condition means and includes to a degree thatone of ordinary skill in the art would understand that the givenparameter, property, or condition is met with a degree of variance, suchas within acceptable manufacturing tolerances. By way of example,depending on the particular parameter, property, or condition that issubstantially met, the parameter, property, or condition may be at least90.0% met, at least 95.0% met, at least 99.0% met, or even at least99.9% met.

As used herein, the term “about” in reference to a given parameter isinclusive of the stated value and has the meaning dictated by thecontext (e.g., it includes the degree of error associated withmeasurement of the given parameter).

What is claimed is:
 1. A method for removing a sulfur compound from ahydrocarbon stream containing the sulfur compound, the methodcomprising: contacting the hydrocarbon stream with an amount of areducing agent effective to react with the sulfur compound to form atleast one reaction product in a treated hydrocarbon stream; and removingthe at least one reaction product from the treated hydrocarbon stream;where: the sulfur compound is selected from the group consisting ofmercaptans having the formula R—S—H where R is a linear or branched C1to C4 alkyl group, carbon disulfide (CS₂), carbonyl sulfide (COS),dialkyl sulfides having the formula R¹—S—R² where R¹ and R² areindependently linear or branched C1 to C4 alkyl groups, dialkyldisulfides having the formula R¹—S—S—R², and combinations thereof; wherethe hydrocarbon stream comprises liquid or gas hydrocarbons selectedfrom the group consisting of C1 to C12 alkanes, C2 to C12 alkenes,liquefied petroleum gas, natural gas, fuel gas, flare gas, naphtha,gasoline, kerosene, and mixtures thereof; and where the reducing agentis selected from the group consisting of: borane (BH₃); diborane (B₂H₆),complexes of borane or diborane with Lewis bases selected from the groupconsisting of ethers, dialkyl sulfides, amines, alcohols, and mixturesthereof; inorganic borohydride salts having the formula M¹BH₄ where M¹is selected from the group consisting of Li, Na, and K, or having theformula M²(BH₄)₂ where M² is selected from the group consisting of Mg,Ca, and Zn; cyanoborohydrides having the formula M¹BH₃CN or having theformula M²(BH₃CN)₂; organic borohydrides having the formula M¹BR³ ₃H andR³ is independently selected from the group consisting of linear orbranched C1 to C3 alkyl groups and a carboxylate group having theformula R⁴C(O)O—, and where R⁴ is selected from the group consisting oflinear or branched C1 to C9 alkyl groups; and combinations thereof. 2.The method of claim 1 where in contacting the hydrocarbon stream withthe reducing agent, the reducing agent is aqueous and has a pH rangingfrom about 7 to about
 14. 3. The method of claim 2 where contacting thehydrocarbon stream with the reducing agent is conducted in the presenceof a base selected from the group consisting of sodium hydroxide,potassium hydroxide, and combinations thereof.
 4. The method of claim 1where the effective amount of the reducing agent is up to two times thestoichiometric ratio of the reducing agent to the sulfur compound. 5.The method of claim 1 where removing the at least one reaction productfrom the hydrocarbon stream comprises a procedure selected from thegroup consisting of: passing the treated hydrocarbon stream through abed containing a solid absorbent selected from the group consisting ofclay, carbon, a zeolite, and combinations thereof; and washing thetreated hydrocarbon stream with a liquid absorbent selected from thegroup consisting of amine-aldehyde condensates, aqueous aldehydes andcombinations thereof.
 6. The method of claim 1 where the reducing agentis in an aqueous solution.
 7. The method of claim 1 where hydrocarbonsin the hydrocarbon stream range from C1-C12.
 8. A method for removing asulfur compound from a hydrocarbon stream containing the sulfurcompound, the method comprising: contacting the hydrocarbon stream withan amount of a reducing agent in an amount up to two times thestoichiometric ratio to react with the sulfur compound to form at leastone reaction product in a treated hydrocarbon stream, where the reducingagent is aqueous and has a pH ranging from about 7 to about 14; andremoving the at least one reaction product from the treated hydrocarbonstream; where: the sulfur compound is selected from the group consistingof mercaptans having the formula R—S—H where R is a linear or branchedC1 to C4 alkyl group, carbon disulfide (CS₂), carbonyl sulfide (COS),dialkyl sulfides having the formula R¹—S—R² where R¹ and R² areindependently linear or branched C1 to C4 alkyl groups, dialkyldisulfides having the formula R¹—S—S—R², and combinations thereof; wherethe hydrocarbon stream comprises liquid or gas hydrocarbons selectedfrom the group consisting of C1 to C12 alkanes, C2 to C12 alkenes,liquefied petroleum gas, natural gas, fuel gas, flare gas, naphtha,gasoline, kerosene, and mixtures thereof; and where the reducing agentis selected from the group consisting of: borane (BH₃); diborane (B₂H₆);complexes of borane or diborane with Lewis bases selected from the groupconsisting of ethers, dialkyl sulfides, amines, alcohols, and mixturesthereof; inorganic borohydride salts having the formula M¹BH₄ where M¹is selected from the group consisting of Li, Na, and K, or having theformula M²(BH₄)₂ where M² is selected from the group consisting of Mg,Ca, and Zn; cyanoborohydrides having the formula M¹BH₃CN or having theformula M²(BH₃CN)₂; organic borohydrides having the formula M¹BR³ ₃H andR³ is independently selected from the group consisting of linear orbranched C1 to C3 alkyl groups and a carboxylate group having theformula R⁴C(O)O—, and where R⁴ is selected from the group consisting oflinear or branched C1 to C9 alkyl groups; and combinations thereof. 9.The method of claim 8 where contacting the hydrocarbon stream with thereducing agent is conducted in the presence of a base selected from thegroup consisting of sodium hydroxide, potassium hydroxide, andcombinations thereof.
 10. The method of claim 8 where removing the atleast one reaction product from the hydrocarbon stream comprises aprocedure selected from the group consisting of: passing the treatedhydrocarbon stream through a bed containing a solid absorbent selectedfrom the group consisting of clay, carbon, a zeolite, and combinationsthereof; and washing the treated hydrocarbon stream with a liquidabsorbent selected from the group consisting of amine-aldehydecondensates, aqueous aldehydes and combinations thereof.
 11. A treatedhydrocarbon stream comprising: liquid or gas light hydrocarbons selectedfrom the group consisting of C1 to C12 alkanes, C2 to C12 alkenes,liquefied petroleum gas, natural gas, fuel gas, flare gas, naphtha,gasoline, kerosene, and mixtures thereof; at least one sulfur compoundselected from the group consisting of mercaptans having the formulaR—S—H where R is a linear or branched C1 to C4 alkyl group, carbondisulfide (CS₂), carbonyl sulfide (COS), dialkyl sulfides having theformula R¹—S—R² where R¹ and R² are independently linear or branched C1to C4 alkyl groups, dialkyl disulfides having the formula R¹—S—S—R²where R¹ and R² are as previously defined, and combinations thereof; andat least one reducing agent selected from the group consisting of:borane (BH₃); diborane (B₂H₆), complexes of borane or diborane withLewis bases selected from the group consisting of ethers, dialkylsulfides, amines, alcohols, and mixtures thereof; inorganic borohydridesalts having the formula M¹BH₄ where M¹ is selected from the groupconsisting of Li, Na, and K, or having the formula M²(BH₄)₂ where M² isselected from the group consisting of Mg, Ca, and Zn; cyanoborohydrideshaving the formula M¹BH₃CN or having the formula M²(BH₃CN)₂; organicborohydrides having the formula M¹BR³ ₃H and R³ is independentlyselected from the group consisting of linear or branched C1 to C3 alkylgroups and a carboxylate group having the formula R⁴C(O)O—, and where R⁴is selected from the group consisting of linear or branched C1 to C9alkyl groups; and combinations thereof; where the reducing agent ispresent in an amount effective to react with the sulfur compound to format least one reaction product.
 12. The treated hydrocarbon stream ofclaim 11 where in contacting the hydrocarbon stream with the reducingagent, the reducing agent is aqueous and has a pH ranging from about 7to about
 14. 13. The treated hydrocarbon stream of claim 12 wherecontacting the hydrocarbon stream with the reducing agent is conductedin the presence of a base selected from the group consisting of sodiumhydroxide, potassium hydroxide, and combinations thereof.
 14. Thetreated hydrocarbon stream of claim 11 where the effective amount of thereducing agent is up to two times the stoichiometric ratio of thereducing agent to the sulfur compound.
 15. The treated hydrocarbonstream of claim 11 where hydrocarbons in the hydrocarbon stream rangefrom C1-C12.